Kerogen and Organic Matter Degrading Additive for Hydraulic Fracturing Fluids

ABSTRACT

Provided in this disclosure, in part, are methods, compositions, and systems for degrading organic matter, such as kerogen, in a subterranean formation. Further, these methods, compositions, and systems allow for increased hydraulic fracturing efficiencies in subterranean formations, such as unconventional rock reservoirs. Also provided in this disclosure is a method of treating kerogen in a subterranean formation including placing in the subterranean formation a composition that includes a first oxidizer including a persulfate and a second oxidizer including a bromate.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No.16/382,089 filed Apr. 11, 2019, which is a continuation application ofU.S. application Ser. No. 15/254,173 filed Sep. 1, 2016, which claimsthe benefit of the filing date of U.S. Provisional Application Ser. No.62/213,744 filed Sep. 3, 2015. The contents of both applications areincorporated by reference in their entirety as part of this application.

TECHNICAL FIELD

This document relates to methods and compositions used in treatingsubterranean formations for enhancing hydrocarbon fluid recovery.

BACKGROUND

Unconventional hydrocarbon reservoirs are reservoirs with trappedhydrocarbons (for example, oil, natural gas, or combinations of them) inwhich the hydrocarbon mobility is limited. Extraction of hydrocarbonsfrom such reservoirs typically involves increasing the mobility of thehydrocarbons, for example, by hydraulic fracturing. In hydraulicfracturing, a fracturing fluid (for example, proppants and one or morechemicals in an aqueous or non-aqueous base fluid) is flowed through thehydrocarbon reservoir at high pressure. The pressure of the fracturingfluid fractures the reservoir rock to increase mobility of the trappedhydrocarbons. Some reservoirs include an organic material called kerogenintertwined with the rock matrix. The kerogen which is intertwinedwithin the rock matrix can drastically increase the tensile strength ofthe rock. As a result, a significant amount of energy can be required topropagate fractures in these reservoirs.

SUMMARY

This disclosure relates to increasing hydraulic fracturing efficienciesin subterranean formations, for example, unconventional rock reservoirs.

Provided in this disclosure, in part, are methods, compositions, andsystems for degrading organic matter, such as kerogen, in a subterraneanformation. Further, these methods, compositions, and systems allow forincreased hydraulic fracturing efficiencies in subterranean formations,such as unconventional rock reservoirs.

Certain aspects of the subject matter described in this disclosure canbe implemented as a method. A composition configured to degrade organicmatter in a subterranean formation—such as kerogen that is intertwinedin a subterranean formation—can be placed into the subterraneanformation as part of a hydraulic fracturing treatment.

This, and other aspects, can include one or more of the followingfeatures. The organic matter can be kerogen and the composition can beconfigured to degrade the kerogen. To degrade the kerogen, thecomposition can reduce the tensile properties of the kerogen renderingthe kerogen partially, substantially, or entirely incapable of affectingthe tensile strength of the reservoir rock. The composition can includean oxidizer. The oxidizer can include hydrogen peroxide or inorganicperoxides. The composition can include a persulfate. The persulfates caninclude potassium persulfate, ammonium persulfate, or a combinationthereof. The composition can include a bromate. The bromates can includesodium bromate. The composition can include a permanganate. Thepermanganate can include potassium permanganate. The composition caninclude an ion or a compound capable of forming an ion. The ion orcompound capable of forming an ion can be a cation or a compound capableof forming a cation. The cation or compound capable of forming thecation can be an imidazolium, an imidazole, an ammonium, an ammonia, apyrrolidinium, a pyrrolidine, pyridinium, a pyridine, a phosphonium or acombination thereof. The cation or compound capable of forming a cationcan also include long or short aliphatic groups. The aliphatic groupscan include ethyl, butyl or hexyl. For example, the cation or compoundcapable of forming a cation can include 1-ethyl-3-methylimidazolium,1-Butyl-1-methylpyrrolidinium, tetrabutylphosphonium, or a combinationthereof. The ion or compound capable of forming an ion can be an anionor a compound capable of forming an anion. The anion or compound capableof forming the anion can include chloride, bromide, iodide,tetrafluoroborate, hexafluorophosphate, sulfonate, or a combinationthereof. A friction reducer can be added to the composition. A catalystcan also be added to the composition. The catalyst can be a metalcatalyst. The fluid can be a hydraulic fracture fluid, a pad fluid thatis flowed into the subterranean formation before a hydraulic fracturefluid, or a combination of them. The composition's release into thesubterranean formation can be delayed. To delay the release of thecomposition into the subterranean formation, the composition can beencapsulated. Byproducts of a chemical reaction between the compositionand the kerogen can be removed from the subterranean formation. Thesubterranean formation can be analyzed for kerogen. The quantity of thecomposition added to the subterranean formation can be determined inresponse to analyzing the subterranean formation for kerogen.

In some embodiments the composition can be encapsulated and configuredto be flowed into a subterranean formation. The encapsulated compositioncan be configured to be slow-released into the subterranean formation.The composition can be configured to degrade organic matter intertwinedwith the subterranean formation. Slow-releasing the composition into thereservoir rock can controllably delay contact between the reservoir rockand the composition to degrade the organic matter.

This, and other aspects, can include one or more of the followingfeatures. The composition can be a hydraulic fracture fluid, a pad fluidthat is flowed into the reservoir before a hydraulic fracture fluid or acombination thereof. The composition can be encapsulated using acoating. The coating can be configured to degrade over time to allow thecomposition to flow through the coating. The coating can be configuredto break during fracture closure releasing the composition.

Also provided in this disclosure is a method of treating kerogen in asubterranean formation that includes placing in the subterraneanformation a composition including a first oxidizer including apersulfate and a second oxidizer including a bromate.

The persulfate can include an ammonium persulfate, a potassiumpersulfate, a sodium persulfate, or a combination thereof. In someembodiments, the persulfate includes an ammonium persulfate.

The persulfate can have a concentration of about 0.00005 M to about 1.00M. For example, the persulfate can have a concentration of about 0.05 Mto about 0.20 M. The persulfate can also have a concentration of about0.05 M to about 0.10 M.

The bromate can include a potassium bromate, a sodium bromate, or acombination thereof. In some embodiments, the bromate includes a sodiumbromate.

The bromate can have a concentration of about 0.00005 M to about 2.00 M.For example, the bromate can have a concentration of about 0.05 M toabout 0.50 M. The bromate can also have a concentration of about 0.05 Mto about 0.20 M.

In some embodiments, the persulfate includes ammonium persulfate and thebromate includes sodium bromate. The ammonium persulfate can have aconcentration of about 0.00005 M to about 1.00 M and the sodium bromatecan have a concentration of about 0.00005 M to about 2.00 M. In someembodiments, the ammonium persulfate has a concentration of about 0.05 Mto about 0.10 M and the sodium bromate has a concentration of about 0.05M to about 0.20 M.

The composition can further include a salt. The salt can includepotassium chloride, sodium chloride, lithium chloride, potassiumbromide, sodium bromide, lithium bromide, ammonium chloride, ammoniumbromide, ammonium iodide, calcium chloride, magnesium chloride,strontium chloride, calcium bromide, magnesium bromide, strontiumbromide, calcium iodide, magnesium iodide, strontium iodide, or acombination thereof. In some embodiments, the salt includes potassiumchloride.

The salt can be present at a concentration of about 0.001 wt % to about20 wt %. For example, the salt can be present at a concentration ofabout 1 wt % to about 10 wt %. In some embodiments, the salt is presentat a concentration of about 2 wt % to about 7 wt %.

In some embodiments, the composition further includes an ion or acompound capable of forming an ion. The ion or the compound capable offorming an ion can include a cation, a compound capable of forming acation, an anion, a compound capable of forming an anion, or combinationthereof. The cation or compound capable of forming a cation can includean imidazolium, an imidazole, an ammonium, an ammonia, a pyrrolidinium,a pyrrolidine, pyridinium, a pyridine, a phosphonium or a combinationthereof. The anion or compound capable of forming an anion can includechloride, bromide, iodide, tetrafluoroborate, hexafluorophosphate,sulfonate, or a combination thereof.

The composition can further include an aqueous liquid. The aqueousliquid can include a water, a brine, a produced water, a flowback water,a brackish water, an Arab-D-brine, a sea water, or a combinationthereof. The aqueous liquid can include a drilling fluid, a fracturingfluid, a diverting fluid, a lost circulation treatment fluid, or acombination thereof.

In some embodiments, the method further includes obtaining or providingthe composition, wherein the obtaining or providing of the compositionoccurs above-surface. In some embodiments, the method further includesobtaining or providing the composition, wherein the obtaining orproviding of the composition occurs in the subterranean formation.

The method can further include combining the composition with an aqueousor oil-based fluid comprising a drilling fluid, stimulation fluid,fracturing fluid, spotting fluid, clean-up fluid, completion fluid,remedial treatment fluid, abandonment fluid, pill, acidizing fluid,cementing fluid, packer fluid, logging fluid, or a combination thereof,to form a mixture, wherein the placing the composition in thesubterranean formation includes placing the mixture in the subterraneanformation.

In some embodiments, at least one of prior to, during, and after theplacing of the composition in the subterranean formation, thecomposition is used in the subterranean formation, at least one of aloneand in combination with other materials, as a drilling fluid,stimulation fluid, fracturing fluid, spotting fluid, clean-up fluid,completion fluid, remedial treatment fluid, abandonment fluid, pill,acidizing fluid, cementing fluid, packer fluid, logging fluid, or acombination thereof.

In some embodiments, the composition further includes saline, aqueousbase, oil, organic solvent, synthetic fluid oil phase, aqueous solution,alcohol or polyol, cellulose, starch, alkalinity control agent, aciditycontrol agent, density control agent, density modifier, emulsifier,dispersant, polymeric stabilizer, crosslinking agent, polyacrylamide,polymer or combination of polymers, antioxidant, heat stabilizer, foamcontrol agent, diluent, plasticizer, filler or inorganic particle,pigment, dye, precipitating agent, rheology modifier, oil-wetting agent,set retarding additive, surfactant, corrosion inhibitor, gas, weightreducing additive, heavy-weight additive, lost circulation material,filtration control additive, salt, fiber, thixotropic additive, breaker,crosslinker, gas, rheology modifier, curing accelerator, curingretarder, pH modifier, chelating agent, scale inhibitor, enzyme, resin,water control material, polymer, oxidizer, a marker, Portland cement,pozzolana cement, gypsum cement, high alumina content cement, slagcement, silica cement, fly ash, metakaolin, shale, zeolite, acrystalline silica compound, amorphous silica, fibers, a hydratableclay, microspheres, pozzolan lime, or a combination thereof.

In some embodiments, the composition further includes a proppant, aresin-coated proppant, or a combination thereof.

The method can further include processing the composition exiting theannulus with at least one fluid processing unit to generate a cleanedcomposition and recirculating the cleaned composition through thewellbore.

In some embodiments, the method further includes fracturing thesubterranean formation. The subterranean formation can be penetrated bya wellbore. The fracturing can include slickwater fracturing.

Also provided in this disclosure is a method of treating kerogen in asubterranean formation that includes placing in a subterranean formationa composition that includes a first oxidizer including an ammoniumpersulfate and a second oxidizer including a sodium bromate. Theammonium persulfate has a concentration of about 0.00005 M to about 0.10M and the sodium bromate has a concentration of about 0.00005 M to about0.20 M.

Further provided in this disclosure is a method of fracturing asubterranean formation penetrated by a wellbore that includes treatingkerogen in the subterranean formation with a composition and fracturingthe subterranean formation. The composition includes a first oxidizerthat includes a persulfate and a second oxidizer that includes abromate. The persulfate has a concentration of about 0.00005 M to about1.0 M and the bromate has a concentration of about 0.00005 M to about0.20 M.

Also provided in this disclosure is a method of treating kerogen in asubterranean formation that includes placing in the subterraneanformation a composition that includes a first oxidizer including anammonium persulfate, a second oxidizer including a sodium bromate, and asalt. The ammonium persulfate has a concentration of about 0.00005 M toabout 0.10 M, the sodium bromate has a concentration of about 0.00005 Mto about 0.20 M, and the salt has a concentration of about 0.001 wt % toabout 10 wt %.

Further provided in this disclosure is a method of fracturing asubterranean formation penetrated by a wellbore that includes treatingkerogen in the subterranean formation with a composition and fracturingthe subterranean formation. The composition includes a first oxidizerthat includes an ammonium persulfate, a second oxidizer that includes asodium bromate and a salt. The ammonium persulfate has a concentrationof about 0.00005 M to about 0.10 M, the sodium bromate has aconcentration of about 0.00005 M to about 0.20 M, and the salt has aconcentration of about 0.001 wt % to about 10 wt %.

Also provided in this disclosure is a method of treating kerogen in asubterranean formation that includes placing in the subterraneanformation a composition including an oxidizer.

In some embodiments, the oxidizer includes hydrogen peroxide, aninorganic peroxide, a bromate, a persulfate, a permanganate, a chlorate,an iodate, a perchlorate, a periodate, a perborate, or a combinationthereof. For example, the oxidizer can include ammonium persulfate,sodium bromate, or a combination thereof. The oxidizer can have aconcentration of about 0.00005 M to about 4.00 M.

In some embodiments, the composition further includes an aqueous liquid.The aqueous liquid can include a brine, a produced water, a flowbackwater, a brackish water, an Arab-D-brine, a sea water, or combinationsthereof.

In some embodiments, the composition further includes a salt. The saltcan be an ammonium salt. The ammonium can include ammonium chloride,ammonium bromide, ammonium iodide, or a combination thereof.

In some embodiments, the method further includes fracturing thesubterranean formation.

Various embodiments of the methods and compositions provided in thisdisclosure provide certain advantages over other methods andcompositions, at least some of which are unexpected. For example, themethods and compositions provided in this disclosure provide

DESCRIPTION OF DRAWINGS

FIG. 1 shows an example of a fracture treatment for a well, as providedin this disclosure.

FIG. 2A shows an image of a reservoir rock at a macro-level. FIG. 2Bshows an image of a reservoir rock matrix at a micro-level. FIG. 2Cshows an image of a reservoir rock at a sub-micro level. FIG. 2D showsan example schematic of reservoir rock at a nano-level. FIG. 2E shows aschematic of kerogen.

FIG. 3 is a flowchart of an example of a process for degrading kerogenin a subterranean formation, as provided in this disclosure.

FIG. 4 shows the degradation of kerogen overtime after treatment with amixture of sodium bromate and ammonium persulfate.

FIG. 5A-5B shows a scanning electron microscope (SEM) image ofkerogen-rich shale.

FIG. 6 shows a shale sample treated with a mixture of ammoniumpersulfate and sodium bromate.

FIG. 7A shows an SEM image of a shale sample containing kerogen. FIG. 7Bshows an SEM image of the same location of the same shale sample afterthe sample was treated with a mixture of ammonium persulfate and sodiumbromate.

DETAILED DESCRIPTION

Reference will now be made in detail to certain embodiments of thedisclosed subject matter, examples of which are illustrated in part inthe accompanying drawings. While the disclosed subject matter will bedescribed in conjunction with the enumerated claims, it will beunderstood that the exemplified subject matter is not intended to limitthe claims to the disclosed subject matter.

Provided in this disclosure, in part, are methods, compositions, andsystems for degrading organic matter, such as kerogen, in a subterraneanformation. Further, these methods, compositions, and systems allow forincreased hydraulic fracturing efficiencies in subterranean formations,such as unconventional rock reservoirs.

The compositions described within this disclosure can be used as akerogen control material to break down, dissolve, or remove all or partsof the kerogen in or near the areas to be hydraulically fractured in asubterranean formation. Using a composition described within thisdisclosure, the kerogen or other organic matter (or both) can be brokendown by, for example, pumping the composition into a subterraneanformation.

The composition can include oxidizers including peroxides such ashydrogen peroxide or other inorganic peroxides, persulfates such aspotassium persulfate or ammonium persulfate, bromates such as sodiumbromate, permanganates such as potassium permanganate, or a combinationthereof.

The composition can further include an ion or a compound capable offorming an ion. The ion or compound capable of forming an ion can be acation or a compound capable of forming a cation. The cation or thecompound capable of forming a cation can be an imidazolium, animidazole, an ammonium, an ammonia, a pyrrolidinium, a pyrrolidine,pyridinium, a pyridine, a phosphonium or a combination thereof. Thecation or compound capable of forming a cation can also include long orshort aliphatic groups. The aliphatic groups can include ethyl, butyl orhexyl. The ion or compound capable of forming an ion can be an anion ora compound capable of forming an anion. The anion or the compoundcapable of forming an anion can include chloride, bromide, iodide,tetrafluoroborate, hexafluorophosphate, sulfonate, or a combinationthereof.

The concentration of the components of the composition (for example, theoxidizers, ions, or compounds capable of forming ions, or a combinationthereof) can depend on the quantity of kerogen or other organic matterin the reservoir rock. For example, the concentration of the oxidizer inthe composition can be high for formations in which the quantity oforganic matter to be removed or partially removed is high.

In some embodiments, the composition includes a friction reducer.

In some embodiments, persulfates can be used for lower temperatureformations. In some embodiments, bromates can be used for highertemperature formations.

In some embodiments, catalysts, for example, metal catalysts, can beadded to the fluid to increase a rate of chemical reaction.

The composition can further include a fracturing fluid or a pad fluidand can be pumped into a subterranean formation before fracturing,during fracturing, or both. In some embodiments, the release of thecomposition including oxidizers can be delayed from a carrier fluid.Delaying the release of the composition from a carrier fluid can beaccomplished by encapsulating the composition. In some embodiments, thecomposition can be encapsulated with coatings through which thecomposition can be slow-released. Alternatively, or in addition, thecoatings can break during fracture closure to release the composition.The composition can be a solid or a powder that can be encapsulated. Adelayed release of the composition can decrease corrosion issues (forexample, in metal tubing in the wellbore through which the fluids aredelivered to the formation) and polymer degradation in the treatingfluid. The polymers subject to degradation include, for example,friction reducers or other polymers used in hydraulic fracturing.

FIG. 1 illustrates an example of a fracture treatment 10 for a well 12.The well 12 can be a reservoir or formation 14, for example, anunconventional reservoir in which recovery operations in addition toconventional recovery operations are practiced to recover trappedhydrocarbons. Examples of unconventional reservoirs include tight-gassands, gas and oil shales, coalbed methane, heavy oil and tar sands, andgas-hydrate deposits. In some implementations, the formation 14 includesan underground formation of naturally fractured rock containinghydrocarbons (for example, oil, gas, or both). For example, theformation 14 can include a fractured shale. In some implementations, thewell 12 can intersect other suitable types of formations 14, includingreservoirs that are not naturally fractured in any significant amount.

The well 12 can include a well bore 20, casing 22 and well head 24. Thewell bore 20 can be a vertical or deviated bore. The casing 22 can becemented or otherwise suitably secured in the well bore 12. Perforations26 can be formed in the casing 22 at the level of the formation 14 toallow oil, gas, and by-products to flow into the well 12 and be producedto the surface 25. Perforations 26 can be formed using shape charges, aperforating gun or otherwise.

For the fracture treatment 10, a work string 30 can be disposed in thewell bore 20. The work string 30 can be coiled tubing, sectioned pipe orother suitable tubing. A fracturing tool 32 can be coupled to an end ofthe work string 30. Packers 36 can seal an annulus 38 of the well bore20 above and below the formation 14. Packers 36 can be mechanical, fluidinflatable or other suitable packers.

One or more pump trucks 40 can be coupled to the work string 30 at thesurface 25. The pump trucks 40 pump fracture fluid 58 down the workstring 30 to perform the fracture treatment 10 and generate the fracture60. The fracture fluid 58 can include a fluid pad, proppants and/or aflush fluid. The pump trucks 40 can include mobile vehicles, equipmentsuch as skids or other suitable structures.

One or more instrument trucks 44 can also be provided at the surface 25.The instrument truck 44 can include a fracture control system 46 and afracture simulator 47. The fracture control system 46 monitors andcontrols the fracture treatment 10. The fracture control system 46 cancontrol the pump trucks 40 and fluid valves to stop and start thefracture treatment 10 as well as to stop and start the pad phase,proppant phase and/or flush phase of the fracture treatment 10. Thefracture control system 46 communicates with surface and/or subsurfaceinstruments to monitor and control the fracture treatment 10. In someimplementations, the surface and subsurface instruments may includesurface sensors 48, down-hole sensors 50 and pump controls 52.

A quantity of energy applied by the fracture control system 46 togenerate the fractures 60 in the reservoir or formation 14 can beaffected not only by the properties of the reservoir rock in theformation but also by the organic matter (for example, kerogen 75)intertwined within the rock matrix. As discussed within this disclosure,kerogen in a reservoir can increase the tensile strength of the rock,for example, by as much as 100-fold, resulting in a correspondingincrease in the ultimate tensile strength of the rock. The high modulusof toughness of the rock-kerogen combination compared to the rock alonecan require a large quantity of energy to generate fractures in such areservoir. Moreover, the presence of kerogen in the reservoir can affectproduction as well. For example, the rubber-like properties ofelastomeric kerogen has a high elasticity, which can prematurely closefractures resulting in decrease in production. Accordingly, the presenceof kerogen in a subterranean formation can decrease an efficiency ofhydraulic fracturing treatments.

This specification describes compositions 81 to degrade the kerogenencountered in subterranean formations, such as at the openings ofcracks in hydraulic fractures. The compositions can include hydraulicfracturing fluids (for example, the fracture fluid 58) and flowedthrough the subterranean formation (for example a reservoir). As orafter the kerogen is degraded, a quantity of energy to generate andpropagate fractures in the subterranean formation (for example areservoir) can decrease, thereby increasing an efficiency (for example,cost, time, long-term effect, etc.) of the fracturing process. Inaddition, fracture length and formation surface exposure after wellboreshut-in can be greater than corresponding parameters in reservoirs inwhich the kerogen has not been degraded. In addition, removing orpartially removing the kerogen and other organic matter from the nearfracture zone can decrease the propensity for the fractures to close(reheal) after the pressure is released from pumping the fracturing,thereby improving the overall productivity of the well.

FIGS. 2A-2E show images and schematics of a multi-scale model ofkerogen-rich rock (for example, shale). For example, FIG. 2A, FIG. 2B,and FIG. 2C show an image of a reservoir rock matrix at a macro-level, amicro-level, and a sub-micro level, respectively. FIGS. 2D and 2E showexamples of schematics of reservoir rock and kerogen, respectively, at anano-level. The image in FIG. 2A is taken at a scale greater than 10⁻³m. The image shows layered composite shale with clay/quartz matrix inlight gray and organic layers in relatively darker gray. The image inFIG. 2B is taken at a scale greater than 10⁻⁵ m. The image shows kerogenand micro-pores distributed through the mineral matrix. Themicro-bedding planes and micro-fractures shown in FIG. 2B demonstratethat failure mechanisms of such composites can be very complex. Forexample, in tensile loadings, the polymer- and rubberlike-kerogenembedded in the shale matrix, at all scales, can augment the tensilerupture, which is related to modulus of toughness, of the granularfractured structure matrix. The image in FIG. 2C is taken at a scalegreater than 10⁻⁷ m. The image shows nano-porous minerals interwovenwith nano-porous organic matter. FIGS. 2D and 2E are schematics taken ata scale greater than 10⁻⁹ m. FIG. 2D is a schematic of elementarycomponents such as clays, for example, illite, smectite. FIG. 2E is aschematic of organic molecules, for example, kerogen molecules.

The compositions described in this disclosure can be used as a kerogencontrol material to break down, dissolve, or remove all or parts of thekerogen in or near the areas to be hydraulically fractured. Using thecompositions described in this disclosure, the kerogen or other organicmatter (or both) can be broken down. To do so, aqueous fluids whichcontain oxidizers can be pumped into the subterranean formation. Forexample, the compositions can include strong oxidizers includingperoxides such as hydrogen peroxide or other inorganic peroxides,persulfates such as potassium persulfate or ammonium persulfate,bromates such as sodium bromate, permanganates such as potassiumpermanganate producing weak organic acids and carbon dioxide.

The byproducts of the reaction between the kerogen and the compositioncan dissipate as gases or can dissolve in an aqueous media of a fluid,such as a fracture fluid. The byproducts can then be removed from theformation during flowback of the fracturing fluid.

FIG. 3 is a flowchart of an example of a process 300 for degradingkerogen in reservoir rock. At 302, a kerogen- and organicmatter-degrading composition (for example composition including anoxidizer) is mixed with a fluid. The fluid can be a hydraulic fracturefluid or a pad fluid that is flowed into the reservoir before thehydraulic fracture fluid (or both). At 308, the composition and thefluid is flowed into the reservoir as part of a hydraulic fracturetreatment. As described above, the kerogen and organic matter degradeupon reacting with the composition. At 310, byproducts of the reactionare removed from the reservoir. For example, the byproducts escape asgases or are pumped out of the reservoir. At 304, friction reducer canbe added to the mixture of the composition and the fluid before pumpingthe fluid into the reservoir at 308. Alternatively or in addition, at306, catalyst can be added to composition and the fluid before pumpingthe fluid into the reservoir at 308.

Method of Treating a Subterranean Formation with a Composition Includingan Oxidizer

Further provided in this disclosure is a method of treating kerogen in asubterranean formation. The method includes placing in the subterraneanformation a composition including an oxidizer.

The oxidizer can include hydrogen peroxide, an inorganic peroxide, abromate, a persulfate, a permanganate, a chlorate, an iodate, aperchlorate, a periodate, a perborate or a combination thereof. Forexample, the oxidizer can include ammonium persulfate, sodium bromate,or a combination thereof. In some embodiments, the oxidizer is ammoniumpersulfate. In some embodiments, the oxidizer is sodium bromate.

The oxidizer can have a concentration of about 0.00005 molar (M) toabout 4.00 M. For example, the bromate can have a concentration of about0.00005, 0.0005, 0.005, 0.05 M, 0.10 M, 0.20 M, 0.30 M, 0.40 M, 0.50 M,0.75 M, 1.0 M, 1.25 M, 1.50 M, 2.0 M, 3.0 M, or about 4.0 M.

The necessary concentration of the oxidizer in the composition can bedetermined based on the oxidizer selected, the on the amount of fluiddownhole at the time of placing the composition into the subterraneanformation, as well as the amount and type of kerogen in the subterraneanformation. Other factors that are relevant for determining theconcentration of oxidizer required include the amount of pyrite or otheriron sulfides in the subterranean formation as well as the amount offriction reducer, viscosifier or other organic component in thetreatment fluid. Further, estimating the rock surface area within thefracture network with which the treatment fluid will make contact in theformation can be considered.

For example, the concentration of the oxidizer can be determined byperforming at least one of the following: (i) performing laboratorytests on kerogen embedded in rock surfaces (for example, etching); (ii)estimating the expected size of the fracture network and the resultingsurface area of the fractured zones; (iii) determine the weight percentof the total organic carbon (TOC) in the formation (for example, byusing a TOC analyzer, pyrolysis unit, well log, or a combinationthereof); (iv) determining the weight percent of iron sulfide in theformation (for example by testing using either x-ray fluorescence, x-raydiffraction, energy dispersive x-ray spectroscopy, well log, or acombination thereof); (v) determining the weight percent of frictionreducer, viscosifier, and other organic materials in the treatmentfluid; and (vi) determining the oxidizer concentration by accounting forthe amount needed to degrade the kerogen while also accounting for theiron sulfide present and any organic materials present in the treatmentfluid.

The composition can further include an ion or compound capable offorming an ion. The ion or compound capable of forming an ion can be acation, a compound capable of forming a cation, an anion, a compoundcapable of forming an anion, or a combination thereof. The ion orcompound capable of forming an ion can include a cation, a compoundcapable of forming a cation, or a combination thereof. The cation or acompound capable of forming a cation can be an imidazolium, animidazole, an ammonium, an ammonia, a pyrrolidinium, a pyrrolidine,pyridinium, a pyridine, a phosphonium or a combination thereof. Thecation or compound capable of forming a cation can also include long orshort aliphatic groups. The aliphatic groups can include ethyl, butyl orhexyl. For example, the cation or compound capable of forming a cationcan include 1-ethyl-3-methylimidazolium, 1-Butyl-1-methylpyrrolidinium,tetrabutylphosphonium, or a combination thereof. The ion or compoundcapable of forming an ion can include an anion, a compound capable offorming an anion, or a combination thereof. The anion can includechloride, bromide, iodide, tetrafluoroborate, hexafluorophosphate,sulfonate, or a combination thereof.

In some embodiments, the composition further includes an aqueous liquid.The aqueous liquid can include a brine, a produced water, a flowbackwater, a brackish water, an Arab-D-brine, a sea water, or a combinationthereof. The aqueous liquid can include a drilling fluid, a fracturingfluid, a diverting fluid, a lost circulation treatment fluid, or acombination thereof.

The composition can further include a salt. In some embodiments, thesalt includes potassium chloride, sodium chloride, lithium chloride,potassium bromide, sodium bromide, lithium bromide, ammonium chloride,ammonium bromide, ammonium iodide, calcium chloride, magnesium chloride,strontium chloride, calcium bromide, magnesium bromide, strontiumbromide, calcium iodide, magnesium iodide, strontium iodide, or acombination thereof. For example, the salt can be an ammonium salt suchas ammonium chloride, ammonium bromide, ammonium iodide, or acombination thereof. In some embodiments, the salt is ammonium chloride.The salt can be present at a concentration of about 0.001 wt % to about30 wt % of the composition, about 0.001 wt % to about 25 wt %, about0.001 wt % to about 20 wt %, about 0.001 wt % to about 15 wt %, or about0.001 wt % to about 10 wt % of the composition. For example, the saltcan be present at a concentration of about 2 wt % to about 7 wt %.

The method can further include fracturing the subterranean formation. Insome embodiments, the fracturing includes slickwater fracturing.

In some embodiments the composition can be encapsulated and configuredto be flowed into a subterranean formation. The encapsulated compositioncan be configured to be slow-released into the subterranean formation.Slow-releasing the composition into the reservoir rock can controllablydelay contact between the reservoir rock and the composition to degradethe organic matter. The encapsulated composition can also be configuredto break during fracture closure releasing the composition.

Method of Treating a Subterranean Formation with a Composition IncludingTwo Oxidizers

Also provided in this disclosure is a method of treating kerogen in asubterranean formation. The method includes placing in the subterraneanformation a composition. The composition includes a first oxidizer thatincludes a persulfate and a second oxidizer that includes a bromate.

A synergism between persulfate oxidizers (such as ammonium persulfate)and bromate oxidizers (such as sodium bromate) for the treatment andbreakdown of kerogen has been discovered.

The persulfate can include an ammonium persulfate, a potassiumpersulfate, a sodium persulfate, or a combination thereof. In someembodiments, the persulfate includes an ammonium persulfate.

The persulfate can have a concentration of about 0.00005 M to about 1.00M. For example, the persulfate can have a concentration of about 0.00005M, 0.0005 M, 0.005, M 0.05 M, 0.10 M, 0.20 M, 0.30 M, 0.40 M, 0.50 M,0.75 M, or about 1.00 M. The persulfate can have a concentration ofabout 0.05 M to about 0.20 M. In some embodiments, the persulfate has aconcentration of about 0.05 M to about 0.10 M. For example, thepersulfate can have a concentration of about 0.05 M, 0.06 M, 0.07 M,0.08 M, 0.09 M, or about 0.10 M.

The concentration of the persulfate can be calculated based on theamount of the persulfate in the composition to be placed in thesubterranean formation. For example, 0.2 grams (g) of ammoniumpersulfate ((NH₄)₂S₂O₈; molecular weight: 228.20) in 10 mL of thecomposition, which is provided as a fluid, would have a molarity of0.0876 M. Alternatively, the concentration of the persulfate can beestimated based on the amount of the persulfate in the composition andthe amount of fluid downhole at the time of placing the composition intothe subterranean formation.

The necessary concentration of the persulfate in the composition canalso be determined based on the on the amount of fluid downhole at thetime of placing the composition into the subterranean formation as wellas the amount and type of kerogen in the subterranean formation.

The bromate can include calcium bromate, magnesium bromate, potassiumbromate, sodium bromate, or a combination thereof. In some embodiments,the bromate includes sodium bromate.

The bromate can have a concentration of about 0.00005 M to about 2.00 M.For example, the bromate can have a concentration of about 0.00005 M,0.0005 M, 0.005 M, 0.05 M, 0.10 M, 0.20 M, 0.30 M, 0.40 M, 0.50 M, 0.75M, 1.0 M, 1.25 M, 1.50 M or about 2.0 M. The bromate can also have aconcentration of about 0.05 M to about 0.50 M. For example, the bromatecan have a concentration of about 0.05 M, 0.10 M, 0.15 M, 0.20 M, 0.30M, 0.40 M, or about 0.50 M. In some embodiments, the bromate can have aconcentration of about 0.05 M to about 0.20 M. For example, the bromatecan have a concentration of about 0.10 M to about 0.15 M.

The concentration of the bromate can be calculated based on the amountof the bromate in the composition to be placed in the subterraneanformation. For example, 0.2 g of sodium bromate (NaBrO₃; molecularweight: 150.89) in 10 mL of the composition, which is provided as afluid, would have a molarity of 0.133 M. Alternatively, theconcentration of the bromate in the composition can be estimated basedon the amount of the bromate in the composition and the amount of fluiddownhole at the time of placing the composition into the subterraneanformation.

The necessary concentration of the bromate in the composition can alsobe determined based on the on the amount of fluid downhole at the timeof placing the composition into the subterranean formation as well asthe amount and type of kerogen in the subterranean formation.

In some embodiments, the persulfate includes ammonium persulfate and thebromate includes sodium bromate. The ammonium persulfate can have aconcentration of about 0.00005 M to about 1.00 M and the sodium bromatecan have a concentration of about 0.00005 M to about 2.00 M. Forexample, the ammonium persulfate can have a concentration of about0.00005 M to about 1.00 M, about 0.0005 M to about 0.75 M, about 0.005 Mto about 0.50 M, about 0.05 M to about 0.40 M, about 0.05 M to about0.30 M, about 0.05 M to about 0.20 M, or about 0.05 M to about 0.10 Mand the sodium bromate can have a concentration of about 0.00005 M toabout 1.50 M, about 0.0005 M to about 1.25 M, about 0.005 M to about1.00 M, about 0.05 M to about 0.75 M, about 0.05 M to about 0.50 M,about 0.05 M to about 0.40 M, about 0.05 M to about 0.30 M, about 0.05 Mto about 0.20 M. In some embodiments, the ammonium persulfate has aconcentration of about 0.05 M to about 0.10 M and the sodium bromate hasa concentration of about 0.05 M to about 0.20 M.

The concentration of the first oxidizer and second oxidizer can also bedetermined by performing at least one of the following: (i) performinglaboratory tests on kerogen embedded in rock surfaces (for example,etching); (ii) estimating the expected size of the fracture network andthe resulting surface area of the fractured zones; (iii) determine theweight percent of the total organic carbon (TOC) in the formation (forexample, by using a TOC analyzer, pyrolysis unit, well log, or acombination thereof); (iv) determining the weight percent of ironsulfide in the formation (for example by testing using either x-rayfluorescence, x-ray diffraction, energy dispersive x-ray spectroscopy,well log, or a combination thereof); (v) determining the weight percentof friction reducer, viscosifier, and other organic materials in thetreatment fluid; and (vi) determining the concentration of the firstoxidizer and second oxidizer by accounting for the amount needed todegrade the kerogen while also accounting for the iron sulfide presentand any organic materials present in the treatment fluid.

The composition can further include a salt. Including a salt in thecomposition can preserve the strength of rock in a subterraneanformation when the rock is contacted with a composition, such as acomposition describe in this disclosure. For example, it has beenobserved that the addition of a salt to a composition of the presentdisclosure can decrease the reduction of a rock's Young's modulus whenthe rock is contacted with a composition, such as a composition describein this disclosure.

In some embodiments, the salt includes potassium chloride, sodiumchloride, lithium chloride, potassium bromide, sodium bromide, lithiumbromide, ammonium chloride, ammonium bromide, ammonium iodide, calciumchloride, magnesium chloride, strontium chloride, calcium bromide,magnesium bromide, strontium bromide, calcium iodide, magnesium iodide,strontium iodide, or a combination thereof. For example, the salt caninclude potassium chloride. The salt can be present at a concentrationof about 0.001 wt % to about 30 wt % of the composition, about 0.001 wt% to about 25 wt %, about 0.001 wt % to about 20 wt %, about 0.001 wt %to about 15 wt %, or about 0.001 wt % to about 10 wt % of thecomposition. For example, the salt can be present at a concentration ofabout 2 wt % to about 7 wt %.

The composition can further include an ion or compound capable offorming an ion. The ion or compound capable of forming an ion can be acation, a compound capable of forming a cation, an anion, a compoundcapable of forming an anion, or a combination thereof. The ion orcompound capable of forming an ion can include a cation, a compoundcapable of forming a cation, or a combination thereof. The cation or acompound capable of forming a cation can be an imidazolium, animidazole, an ammonium, an ammonia, a pyrrolidinium, a pyrrolidine,pyridinium, a pyridine, a phosphonium or a combination thereof. The ionor compound capable of forming an ion can include an anion, a compoundcapable of forming an anion, or a combination thereof. The anion caninclude chloride, bromide, iodide, tetrafluoroborate,hexafluorophosphate, sulfonate, or a combination thereof.

In some embodiments, the composition further includes an aqueous liquid.The aqueous liquid can include a brine, a produced water, a flowbackwater, a brackish water, an Arab-D-brine, a sea water, or a combinationthereof. The aqueous liquid can include a drilling fluid, a fracturingfluid, a diverting fluid, a lost circulation treatment fluid, or acombination thereof.

The method can also include obtaining or providing the composition,wherein the obtaining or providing of the composition occursabove-surface. In some embodiments, the method includes obtaining orproviding the composition, wherein the obtaining or providing of thecomposition occurs in the subterranean formation. For example, the firstoxidizer including a persulfate can initially be placed in thesubterranean formation and, at a later time, the second oxidizerincluding a bromate can be placed in the subterranean formation.Alternatively, the second oxidizer including a bromate can initially beplaced in the subterranean formation and, at a later time, the firstoxidizer including a persulfate can be placed in the subterraneanformation.

The method can also further include combining the composition with anaqueous or oil-based fluid including a drilling fluid, stimulationfluid, fracturing fluid, spotting fluid, clean-up fluid, completionfluid, remedial treatment fluid, abandonment fluid, pill, acidizingfluid, cementing fluid, packer fluid, logging fluid, or a combinationthereof, to form a mixture, wherein the placing the composition in thesubterranean formation includes placing the mixture in the subterraneanformation.

In some embodiments, at least one of prior to, during, and after theplacing of the composition in the subterranean formation, thecomposition is used in the subterranean formation, at least one of aloneor in combination with other materials, as a drilling fluid, stimulationfluid, fracturing fluid, spotting fluid, clean-up fluid, completionfluid, remedial treatment fluid, abandonment fluid, pill, acidizingfluid, cementing fluid, packer fluid, logging fluid, or a combinationthereof.

The composition can also further include a saline, an aqueous base, anoil, an organic solvent, a synthetic fluid oil phase, an aqueoussolution, an alcohol or polyol, a cellulose, a starch, an alkalinitycontrol agent, an acidity control agent, a density control agent, adensity modifier, an emulsifier, a dispersant, a polymeric stabilizer, acrosslinking agent, a polyacrylamide, a polymer or combination ofpolymers, an antioxidant, a heat stabilizer, a foam control agent, adiluent, a plasticizer, a filler or inorganic particle, a pigment, adye, a precipitating agent, a rheology modifier, an oil-wetting agent, aset retarding additive, a surfactant, a corrosion inhibitor, a gas, aweight reducing additive, a heavy-weight additive, a lost circulationmaterial, a filtration control additive, a salt, a fiber, a thixotropicadditive, a breaker, a curing accelerator, a curing retarder, a pHmodifier, chelating agent, a scale inhibitor, an enzyme, a resin, awater control material, an additional oxidizer, a marker, a Portlandcement, pozzolana cement, a gypsum cement, a high alumina contentcement, a slag cement, a silica cement, a fly ash, a metakaolin, ashale, a zeolite, a crystalline silica compound, an amorphous silica, ahydratable clay, a microsphere, a pozzolan lime, or a combinationthereof.

In some embodiments the composition can further include a proppant, aresin-coated proppant, or a combination thereof.

In some embodiments, the method further includes processing thecomposition exiting the annulus with at least one fluid processing unitto generate a cleaned composition and recirculating the cleanedcomposition into the subterranean formation.

The method can further include fracturing the subterranean formation. Insome embodiments, the fracturing includes slickwater fracturing. Theslickwater fracturing can employ a low viscosity aqueous fluid to inducea subterranean fracture. The slickwater fluids can include a fresh wateror a brine having sufficient friction reducing agents to minimize thetubular friction pressures. Such fluids can have viscosities that areslightly higher than unmodified fresh water or brine.

Also provided in this disclosure is a method of treating kerogen in asubterranean formation, that includes placing in the subterraneanformation a composition including a first oxidizer including an ammoniumpersulfate and a second oxidizer including a sodium bromate. Theammonium persulfate has a concentration of about 0.05 M to about 0.10 Mand the sodium bromate has a concentration of about 0.05 M to about 0.20M.

Further provided in this disclosure is a method of fracturing asubterranean formation penetrated by a wellbore. The method includestreating kerogen in the subterranean formation with a compositionincluding a first oxidizer including a persulfate and a second oxidizercomprising a bromate. The method further includes fracturing thesubterranean formation. In some embodiments the persulfate has aconcentration of about 0.05 M to about 1.0 M and the bromate has aconcentration of about 0.05 M to about 0.20 M.

Also provided in this disclosure is a method of treating kerogen asubterranean formation that includes placing in the subterraneanformation a composition that includes a first oxidizer including anammonium persulfate, a second oxidizer including a sodium bromate, and asalt. In some embodiments, the ammonium persulfate has a concentrationof about 0.05 M to about 0.10 M, the sodium bromate has a concentrationof about 0.05 M to about 0.20 M, and the salt has a concentration ofabout 0.001 wt % to about 10 wt %.

Further provided in this disclosure is a method of fracturing asubterranean formation penetrated by a wellbore that includes treatingkerogen in the subterranean formation with a composition including afirst oxidizer including an ammonium persulfate, a second oxidizerincluding a sodium bromate, and a salt. The method further includesfracturing the subterranean formation.

In some embodiments, the ammonium persulfate has a concentration ofabout 0.00005 M to about 0.10 M, the sodium bromate has a concentrationof about 0.00005 M to about 0.20 M, and the salt has a concentration ofabout 0.001 wt % to about 10 wt %.

Compositions Including Two Oxidizers

Further provided in this disclosure is a composition. The compositionincludes a first oxidizer that includes a persulfate and a secondoxidizer that includes a bromate.

The persulfate can include an ammonium persulfate, a potassiumpersulfate, a sodium persulfate, and combinations thereof. In someembodiments, the persulfate includes an ammonium persulfate.

The persulfate can have a concentration of about 0.00005 M to about 1.00M. For example, the persulfate can have a concentration of about 0.00005M, 0.0005 M, 0.005, M 0.05 M, 0.10 M, 0.20 M, 0.30 M, 0.40 M, 0.50 M,0.75 M, or about 1.00 M. The persulfate can have a concentration ofabout 0.05 M to about 0.20 M. In some embodiments, the persulfate has aconcentration of about 0.05 M to about 0.10 M. For example, thepersulfate can have a concentration of about 0.05 M, 0.06 M, 0.07 M,0.08 M, 0.09 M, or about 0.10 M.

The bromate can include calcium bromate, magnesium bromate, potassiumbromate, sodium bromate, or a combination thereof. In some embodiments,the bromate includes sodium bromate.

The bromate can have a concentration of about 0.00005 M to about 2.00 M.For example, the bromate can have a concentration of about 0.00005 M,0.0005 M, 0.005 M, 0.05 M, 0.10 M, 0.20 M, 0.30 M, 0.40 M, 0.50 M, 0.75M, 1.0 M, 1.25 M, 1.50 M or about 2.0 M. The bromate can also have aconcentration of about 0.05 M to about 0.50 M. For example, the bromatecan have a concentration of about 0.05 M, 0.10 M, 0.15 M, 0.20 M, 0.30M, 0.40 M, or about 0.50 M. In some embodiments, the bromate can have aconcentration of about 0.05 M to about 0.20 M. For example, the bromatecan have a concentration of about 0.10 M to about 0.15 M.

In some embodiments, the persulfate includes ammonium persulfate and thebromate includes sodium bromate. The ammonium persulfate can have aconcentration of about 0.00005 M to about 1.00 M and the sodium bromatecan have a concentration of about 0.00005 M to about 2.00 M. Forexample, the ammonium persulfate can have a concentration of about0.00005 M to about 1.00 M, about 0.0005 M to about 0.75 M, about 0.005 Mto about 0.50 M, about 0.05 M to about 0.40 M, about 0.05 M to about0.30 M, about 0.05 M to about 0.20 M, or about 0.05 M to about 0.10 Mand the sodium bromate can have a concentration of about 0.00005 M toabout 1.50 M, about 0.0005 M to about 1.25 M, about 0.005 M to about1.00 M, about 0.05 M to about 0.75 M, about 0.05 M to about 0.50 M,about 0.05 M to about 0.40 M, about 0.05 M to about 0.30 M, about 0.05 Mto about 0.20 M. In some embodiments, the ammonium persulfate has aconcentration of about 0.05 M to about 0.10 M and the sodium bromate hasa concentration of about 0.05 M to about 0.20 M.

In some embodiments, the salt includes potassium chloride, sodiumchloride, lithium chloride, potassium bromide, sodium bromide, lithiumbromide, ammonium chloride, ammonium bromide, ammonium iodide, calciumchloride, magnesium chloride, strontium chloride, calcium bromide,magnesium bromide, strontium bromide, calcium iodide, magnesium iodide,strontium iodide, or a combination thereof. For example, the salt caninclude potassium chloride. The salt can be present at a concentrationof about 0.001 wt % to about 30 wt % of the composition, about 0.001 wt% to about 25 wt %, about 0.001 wt % to about 20 wt %, about 0.001 wt %to about 15 wt %, or about 0.001 wt % to about 10 wt % of thecomposition. For example, the salt can be present at a concentration ofabout 2 wt % to about 7 wt %.

The composition can further include an ion or compound capable offorming an ion. The ion or compound capable of forming an ion can be acation or a compound capable of forming a cation. The cation or acompound capable of forming a cation can be an imidazolium, animidazole, an ammonium, an ammonia, a pyrrolidinium, a pyrrolidine,pyridinium, a pyridine, a phosphonium or a combination thereof. The ionor compound capable of forming an ion can include an anion or a compoundcapable of forming an anion. The anion can include chloride, bromide,iodide, tetrafluoroborate, hexafluorophosphate, sulfonate, or acombination thereof.

In some embodiments, the composition further includes an aqueous liquid.The aqueous liquid can include a brine, a produced water, a flowbackwater, a brackish water, an Arab-D-brine, a sea water, or a combinationthereof. The aqueous liquid can be include a drilling fluid, afracturing fluid, a diverting fluid, a lost circulation treatment fluid,or a combination thereof.

Other Components

The compositions described in this disclosure can further include one ormore suitable components. The additional components can be anycomponents, such that the composition can be used as described in thisdisclosure.

In some embodiments, the composition includes one or more viscosifiers.The viscosifier can be any suitable viscosifier. The viscosifier canaffect the viscosity of the composition or a solvent that contacts thecomposition at any suitable time and location. In some embodiments, theviscosifier provides an increased viscosity at least one of beforeinjection into the subterranean formation, at the time of injection intothe subterranean formation, during travel through a tubular disposed ina borehole, once the composition reaches a particular subterraneanlocation, or some period of time after the composition reaches aparticular subterranean location. In some embodiments, the viscosifiercan be about 0.0001 wt % to about 10 wt % of the composition.

The viscosifier can include at least one of a linear polysaccharide, andpoly((C₂-C₁₀)alkenylene), in which at each occurrence, the(C₂-C₁₀)alkenylene is independently substituted or unsubstituted. Insome embodiments, the viscosifier can include at least one ofpoly(acrylic acid) or (C₁-C₅)alkyl esters thereof, poly(methacrylicacid) or (C₁-C₅)alkyl esters thereof, poly(vinyl acetate), poly(vinylalcohol), poly(ethylene glycol), poly(vinyl pyrrolidone),polyacrylamide, poly (hydroxyethyl methacrylate), alginate, chitosan,curdlan, dextran, emulsan, gellan, glucuronan, N-acetyl-glucosamine,N-acetyl-heparosan, hyaluronic acid, kefiran, lentinan, levan, mauran,pullulan, scleroglucan, schizophyllan, stewartan, succinoglycan,xanthan, welan, derivatized starch, tamarind, tragacanth, guar gum,derivatized guar (for example, hydroxypropyl guar, carboxy methyl guar,or carboxymethyl hydroxylpropyl guar), gum ghatti, gum arabic, locustbean gum, and derivatized cellulose (for example, carboxymethylcellulose, hydroxyethyl cellulose, carboxymethyl hydroxyethyl cellulose,hydroxypropyl cellulose, or methyl hydroxyl ethyl cellulose).

The viscosifier can include a poly(vinyl alcohol) homopolymer,poly(vinyl alcohol) copolymer, a crosslinked poly(vinyl alcohol)homopolymer, and a crosslinked poly(vinyl alcohol) copolymer. Theviscosifier can include a poly(vinyl alcohol) copolymer or a crosslinkedpoly(vinyl alcohol) copolymer including at least one of a graft, linear,branched, block, and random copolymer of vinyl alcohol and at least oneof a substituted or unsubstituted (C₂-C₅₀)hydrocarbyl having at leastone aliphatic unsaturated C—C bond therein, and a substituted orunsubstituted (C₂-C₅₀)alkene. The viscosifier can include a poly(vinylalcohol) copolymer or a crosslinked poly(vinyl alcohol) copolymerincluding at least one of a graft, linear, branched, block, and randomcopolymer of vinyl alcohol and at least one of vinyl phosphonic acid,vinylidene diphosphonic acid, substituted or unsubstituted2-acrylamido-2-methylpropanesulfonic acid, a substituted orunsubstituted (C₁-C₂₀)alkenoic acid, propenoic acid, butenoic acid,pentenoic acid, hexenoic acid, octenoic acid, nonenoic acid, decenoicacid, acrylic acid, methacrylic acid, hydroxypropyl acrylic acid,acrylamide, fumaric acid, methacrylic acid, hydroxypropyl acrylic acid,vinyl phosphonic acid, vinylidene diphosphonic acid, itaconic acid,crotonic acid, mesoconic acid, citraconic acid, styrene sulfonic acid,allyl sulfonic acid, methallyl sulfonic acid, vinyl sulfonic acid, and asubstituted or unsubstituted (C₁-C₂₀)alkyl ester thereof. Theviscosifier can include a poly(vinyl alcohol) copolymer or a crosslinkedpoly(vinyl alcohol) copolymer including at least one of a graft, linear,branched, block, and random copolymer of vinyl alcohol and at least oneof vinyl acetate, vinyl propanoate, vinyl butanoate, vinyl pentanoate,vinyl hexanoate, vinyl 2-methyl butanoate, vinyl 3-ethylpentanoate, andvinyl 3-ethylhexanoate, maleic anhydride, a substituted or unsubstituted(C₁-C₂₀)alkenoic substituted or unsubstituted (C₁-C₂₀)alkanoicanhydride, a substituted or unsubstituted (C₁-C₂₀)alkenoic substitutedor unsubstituted (C₁-C₂₀)alkenoic anhydride, propenoic acid anhydride,butenoic acid anhydride, pentenoic acid anhydride, hexenoic acidanhydride, octenoic acid anhydride, nonenoic acid anhydride, decenoicacid anhydride, acrylic acid anhydride, fumaric acid anhydride,methacrylic acid anhydride, hydroxypropyl acrylic acid anhydride, vinylphosphonic acid anhydride, vinylidene diphosphonic acid anhydride,itaconic acid anhydride, crotonic acid anhydride, mesoconic acidanhydride, citraconic acid anhydride, styrene sulfonic acid anhydride,allyl sulfonic acid anhydride, methallyl sulfonic acid anhydride, vinylsulfonic acid anhydride, and an N—(C₁-C₁₀)alkenyl nitrogen containingsubstituted or unsubstituted (C₁-C₁₀)heterocycle. The viscosifier caninclude a poly(vinyl alcohol) copolymer or a crosslinked poly(vinylalcohol) copolymer including at least one of a graft, linear, branched,block, and random copolymer that includes apoly(vinylalcohol)-poly(acrylamide) copolymer, apoly(vinylalcohol)-poly(2-acrylamido-2-methylpropanesulfonic acid)copolymer, or a poly(vinylalcohol)-poly(N-vinylpyrrolidone) copolymer.The viscosifier can include a crosslinked poly(vinyl alcohol)homopolymer or copolymer including a crosslinker including at least oneof an aldehyde, an aldehyde-forming compound, a carboxylic acid or anester thereof, a sulfonic acid or an ester thereof, a phosphonic acid oran ester thereof, an acid anhydride, and an epihalohydrin.

The composition can further include a crosslinker. The crosslinker canbe any suitable crosslinker. The crosslinker can be present in anysuitable concentration, such as more, less, or an equal concentration ascompared to the concentration of the crosslinker. The crosslinker caninclude at least one of boric acid, borax, a borate, a(C₁-C₃₀)hydrocarbylboronic acid, a (C₁-C₃₀)hydrocarbyl ester of a(C₁-C₃₀)hydrocarbylboronic acid, a (C₁-C₃₀)hydrocarbylboronicacid-modified polyacrylamide, ferric chloride, disodium octaboratetetrahydrate, sodium metaborate, sodium diborate, sodium tetraborate,disodium tetraborate, a pentaborate, ulexite, colemanite, magnesiumoxide, zirconium lactate, zirconium triethanol amine, zirconium lactatetriethanolamine, zirconium carbonate, zirconium acetylacetonate,zirconium malate, zirconium citrate, zirconium diisopropylamine lactate,zirconium glycolate, zirconium triethanol amine glycolate, zirconiumlactate glycolate, titanium lactate, titanium malate, titanium citrate,titanium ammonium lactate, titanium triethanolamine, titaniumacetylacetonate, aluminum lactate, and aluminum citrate. The compositioncan include any suitable proportion of the crosslinker, such as about0.1 wt % to about 50 wt %, or about 0.1 wt % to about 20 wt %, or about0.001 wt %, 0.01, 0.1, 1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50, 60, 70,80, 85, 90, 91, 92, 93, 94, 95, 96, 97, 98, or about 99 wt % or more ofthe composition.

In some embodiments, the composition, or a mixture including the same,can include any suitable amount of any suitable material used in adownhole fluid. For example, the composition or a mixture including thesame can include water, saline, aqueous base, acid, oil, organicsolvent, synthetic fluid oil phase, aqueous solution, alcohol or polyol,cellulose, starch, alkalinity control agents, acidity control agents,density control agents, density modifiers, emulsifiers, dispersants,polymeric stabilizers, crosslinking agents, polyacrylamide, a polymer orcombination of polymers, antioxidants, heat stabilizers, foam controlagents, solvents, diluents, plasticizer, filler or inorganic particle,pigment, dye, precipitating agent, rheology modifier, oil-wettingagents, set retarding additives, surfactants, gases, weight reducingadditives, heavy-weight additives, lost circulation materials,filtration control additives, fibers, thixotropic additives, breakers,crosslinkers, rheology modifiers, curing accelerators, curing retarders,pH modifiers, chelating agents, scale inhibitors, enzymes, resins, watercontrol materials, oxidizers, markers, Portland cement, pozzolanacement, gypsum cement, high alumina content cement, slag cement, silicacement, fly ash, metakaolin, shale, zeolite, a crystalline silicacompound, amorphous silica, hydratable clays, microspheres, lime, or acombination thereof.

A drilling fluid, also known as a drilling mud or simply “mud,” is aspecially designed fluid that is circulated through a wellbore as thewellbore is being drilled to facilitate the drilling operation. Thedrilling fluid can be water-based or oil-based. The drilling fluid cancarry cuttings up from beneath and around the bit, transport them up theannulus, and allow their separation. Also, a drilling fluid can cool andlubricate the drill head as well as reduce friction between the drillstring and the sides of the hole. The drilling fluid aids in support ofthe drill pipe and drill head, and provides a hydrostatic head tomaintain the integrity of the wellbore walls and prevent well blowouts.Specific drilling fluid systems can be selected to optimize a drillingoperation in accordance with the characteristics of a particulargeological formation. The drilling fluid can be formulated to preventunwanted influxes of formation fluids from permeable rocks and also toform a thin, low permeability filter cake that temporarily seals pores,other openings, and formations penetrated by the bit. In water-baseddrilling fluids, solid particles are suspended in a water or brinesolution containing other components. Oils or other non-aqueous liquidscan be emulsified in the water or brine or at least partiallysolubilized (for less hydrophobic non-aqueous liquids), but water is thecontinuous phase. A drilling fluid can be present in the mixture withthe composition including the crosslinkable ampholyte polymer and thecrosslinker, or a crosslinked reaction product thereof, in any suitableamount, such as about 1 wt % or less, about 2 wt %, 3, 4, 5, 10, 15, 20,30, 40, 50, 60, 70, 80, 85, 90, 95, 96, 97, 98, 99, 99.9, 99.99, 99.999,or about 99.9999 wt % or more of the mixture.

A water-based drilling fluid in methods provided in this disclosure canbe any suitable water-based drilling fluid. In various embodiments, thedrilling fluid can include at least one of water (fresh or brine), asalt (for example, calcium chloride, sodium chloride, potassiumchloride, magnesium chloride, calcium bromide, sodium bromide, potassiumbromide, calcium nitrate, sodium formate, potassium formate, cesiumformate), aqueous base (for example, sodium hydroxide or potassiumhydroxide), alcohol or polyol, cellulose, starches, alkalinity controlagents, density control agents such as a density modifier (for example,barium sulfate), surfactants (for example, betaines, alkali metalalkylene acetates, sultaines, ether carboxylates), emulsifiers,dispersants, polymeric stabilizers, crosslinking agents,polyacrylamides, polymers or combinations of polymers, antioxidants,heat stabilizers, foam control agents, foaming agents, solvents,diluents, plasticizers, filler or inorganic particles (for example,silica), pigments, dyes, precipitating agents (for example, silicates oraluminum complexes), and rheology modifiers such as thickeners orviscosifiers (for example, xanthan gum). Any ingredient listed in thisparagraph can be either present or not present in the mixture.

An oil-based drilling fluid or mud in methods provided in thisdisclosure can be any suitable oil-based drilling fluid. In variousembodiments the drilling fluid can include at least one of an oil-basedfluid (or synthetic fluid), saline, aqueous solution, emulsifiers, otheragents of additives for suspension control, weight or density control,oil-wetting agents, fluid loss or filtration control agents, andrheology control agents. For example, see H. C. H. Darley and George R.Gray, Composition and Properties of Drilling and Completion Fluids66-67, 561-562 (5th ed. 1988). An oil-based or invert emulsion-baseddrilling fluid can include between about 10:90 to about 95:5, or about50:50 to about 95:5, by volume of oil phase to water phase. Asubstantially all oil mud includes about 100% liquid phase oil by volume(for example, substantially no internal aqueous phase).

A pill is a relatively small quantity (for example, less than about 500bbl, or less than about 200 bbl) of drilling fluid used to accomplish aspecific task that the regular drilling fluid cannot perform. Forexample, a pill can be a high-viscosity pill to, for example, help liftcuttings out of a vertical wellbore. In another example, a pill can be afreshwater pill to, for example, dissolve a salt formation. Anotherexample is a pipe-freeing pill to, for example, destroy filter cake andrelieve differential sticking forces. In another example, a pill is alost circulation material pill to, for example, plug a thief zone. Apill can include any component described in this disclosure as acomponent of a drilling fluid.

A cement fluid can include an aqueous mixture of at least one of cementand cement kiln dust. The composition including the crosslinkableampholyte polymer and the crosslinker, or a crosslinked reaction productthereof, can form a useful combination with cement or cement kiln dust.The cement kiln dust can be any suitable cement kiln dust. Cement kilndust can be formed during the manufacture of cement and can be partiallycalcined kiln feed that is removed from the gas stream and collected ina dust collector during a manufacturing process. Cement kiln dust can beadvantageously utilized in a cost-effective manner since kiln dust isoften regarded as a low value waste product of the cement industry. Someembodiments of the cement fluid can include cement kiln dust but nocement, cement kiln dust and cement, or cement but no cement kiln dust.The cement can be any suitable cement. The cement can be a hydrauliccement. A variety of cements can be utilized in accordance withembodiments of the methods described in this disclosure; for example,those including calcium, aluminum, silicon, oxygen, iron, or sulfur,which can set and harden by reaction with water. Suitable cements caninclude Portland cements, pozzolana cements, gypsum cements, highalumina content cements, slag cements, silica cements, and combinationsthereof. In some embodiments, the Portland cements that are suitable foruse in embodiments of the methods described in this disclosure areclassified as Classes A, C, H, and G cements according to the AmericanPetroleum Institute, API Specification for Materials and Testing forWell Cements, API Specification 10, Fifth Ed., Jul. 1, 1990. A cementcan be generally included in the cementing fluid in an amount sufficientto provide the desired compressive strength, density, or cost. In someembodiments, the hydraulic cement can be present in the cementing fluidin an amount in the range of from 0 wt % to about 100 wt %, 0-95 wt %,20-95 wt %, or about 50-90 wt %. A cement kiln dust can be present in anamount of at least about 0.01 wt %, or about 5 wt %-80 wt %, or about 10wt % to about 50 wt %.

Optionally, other additives can be added to a cement or kilndust-containing composition of embodiments of the methods described inthis disclosure as deemed appropriate by one skilled in the art, withthe benefit of this disclosure. Any optional ingredient listed in thisparagraph can be either present or not present in the composition. Forexample, the composition can include fly ash, metakaolin, shale,zeolite, set retarding additive, surfactant, a gas, accelerators, weightreducing additives, heavy-weight additives, lost circulation materials,filtration control additives, dispersants, and combinations thereof. Insome examples, additives can include crystalline silica compounds,amorphous silica, salts, fibers, hydratable clays, microspheres,pozzolan lime, thixotropic additives, combinations thereof, and thelike.

The composition or mixture can further include a proppant, aresin-coated proppant, an encapsulated resin, or a combination thereof.A proppant is a material that keeps an induced hydraulic fracture atleast partially open during or after a fracturing treatment. Proppantscan be transported into the subterranean formation and to the fractureusing fluid, such as fracturing fluid or another fluid. Ahigher-viscosity fluid can more effectively transport proppants to adesired location in a fracture, especially larger proppants, by moreeffectively keeping proppants in a suspended state within the fluid.Examples of proppants can include sand, gravel, glass beads, polymerbeads, ground products from shells and seeds such as walnut hulls, andmanmade materials such as ceramic proppant, bauxite, tetrafluoroethylenematerials (for example, TEFLON™ available from DuPont), fruit pitmaterials, processed wood, composite particulates prepared from a binderand fine grade particulates such as silica, alumina, fumed silica,carbon black, graphite, mica, titanium dioxide, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, and solid glass, or mixtures thereof. In some embodiments,proppant can have an average particle size, in which particle size isthe largest dimension of a particle, of about 0.001 mm to about 3 mm,about 0.15 mm to about 2.5 mm, about 0.25 mm to about 0.43 mm, about0.43 mm to about 0.85 mm, about 0.85 mm to about 1.18 mm, about 1.18 mmto about 1.70 mm, or about 1.70 to about 2.36 mm. In some embodiments,the proppant can have a distribution of particle sizes clustering aroundmultiple averages, such as one, two, three, or four different averageparticle sizes. The composition or mixture can include any suitableamount of proppant, such as about 0.000, 1 wt % to about 99.9 wt %,about 0.1 wt % to about 80 wt %, or about 10 wt % to about 60 wt %, orabout 0.000, 000, 01 wt % or less, or about 0.000001 wt %, 0.0001,0.001, 0.01, 0.1, 1, 2, 3, 4, 5, 10, 15, 20, 30, 40, 50, 60, 70, 80, 85,90, 91, 92, 93, 94, 95, 96, 97, 98, 99, 99.9 wt %, or about 99.99 wt %or more.

Values expressed in a range format should be interpreted in a flexiblemanner to include not only the numerical values explicitly recited asthe limits of the range, but also to include all the individualnumerical values or sub-ranges encompassed within that range as if eachnumerical value and sub-range is explicitly recited. For example, arange of “about 0.1% to about 5%” or “about 0.1% to 5%” should beinterpreted to include not just about 0.1% to about 5%, but also theindividual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges(for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within theindicated range. The statement “about X to Y” has the same meaning as“about X to about Y,” unless indicated otherwise. Likewise, thestatement “about X, Y, or about Z” has the same meaning as “about X,about Y, or about Z,” unless indicated otherwise.

In this document, the terms “a,” “an,” or “the” are used to include oneor more than one unless the context clearly dictates otherwise. The term“or” is used to refer to a nonexclusive “or” unless otherwise indicated.The statement “at least one of A and B” has the same meaning as “A, B,or A and B.” In addition, it is to be understood that the phraseology orterminology employed in this disclosure, and not otherwise defined, isfor the purpose of description only and not of limitation. Any use ofsection headings is intended to aid reading of the document and is notto be interpreted as limiting; information that is relevant to a sectionheading may occur within or outside of that particular section.

All publications, patents, and patent documents referred to in thisdocument are incorporated by reference in this disclosure in theirentirety, as though individually incorporated by reference. In the eventof inconsistent usages between this document and those documents soincorporated by reference, the usage in the incorporated referenceshould be considered supplementary to that of this document; forirreconcilable inconsistencies, the usage in this document controls.

In the methods of manufacturing described in this disclosure, the actscan be carried out in any order, except when a temporal or operationalsequence is explicitly recited. Furthermore, specified acts can becarried out concurrently unless explicit claim language recites thatthey be carried out separately. For example, a claimed act of doing Xand a claimed act of doing Y can be conducted simultaneously within asingle operation, and the resulting process will fall within the literalscope of the claimed process.

The term “about” as used in this disclosure can allow for a degree ofvariability in a value or range, for example, within 10%, within 5%, orwithin 1% of a stated value or of a stated limit of a range.

The term “substantially” as used in this disclosure refers to a majorityof, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%,97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

The term “solvent” as used in this disclosure refers to a liquid thatcan dissolve a solid, another liquid, or a gas to form a solution.Non-limiting examples of solvents are silicones, organic compounds,water, alcohols, ionic liquids, and supercritical fluids.

The term “room temperature” as used in this disclosure refers to atemperature of about 15° C. to about 28° C.

The term “standard temperature and pressure” as used in this disclosurerefers to 20° C. and 101 kPa.

The term “downhole” as used in this disclosure refers to under thesurface of the earth, such as a location within or fluidly connected toa wellbore.

As used in this disclosure, the term “drilling fluid” refers to fluids,slurries, or muds used in drilling operations downhole, such as duringthe formation of the wellbore.

As used in this disclosure, the term “stimulation fluid” refers tofluids or slurries used downhole during stimulation activities of thewell that can increase the production of a well, including perforationactivities. In some examples, a stimulation fluid can include afracturing fluid or an acidizing fluid.

As used in this disclosure, the term “clean-up fluid” refers to fluidsor slurries used downhole during clean-up activities of the well, suchas any treatment to remove material obstructing the flow of desiredmaterial from the subterranean formation. In one example, a clean-upfluid can be an acidification treatment to remove material formed by oneor more perforation treatments. In another example, a clean-up fluid canbe used to remove a filter cake.

As used in this disclosure, the term “fracturing fluid” refers to fluidsor slurries used downhole during fracturing operations.

As used in this disclosure, the term “spotting fluid” refers to fluidsor slurries used downhole during spotting operations, and can be anyfluid designed for localized treatment of a downhole region. In oneexample, a spotting fluid can include a lost circulation material fortreatment of a specific section of the wellbore, such as to seal offfractures in the wellbore and prevent sag. In another example, aspotting fluid can include a water control material. In some examples, aspotting fluid can be designed to free a stuck piece of drilling orextraction equipment, can reduce torque and drag with drillinglubricants, prevent differential sticking, promote wellbore stability,and can help to control mud weight.

As used in this disclosure, the term “completion fluid” refers to fluidsor slurries used downhole during the completion phase of a well,including cementing compositions.

As used in this disclosure, the term “remedial treatment fluid” refersto fluids or slurries used downhole for remedial treatment of a well.Remedial treatments can include treatments designed to increase ormaintain the production rate of a well, such as stimulation or clean-uptreatments.

As used in this disclosure, the term “abandonment fluid” refers tofluids or slurries used downhole during or preceding the abandonmentphase of a well.

As used in this disclosure, the term “acidizing fluid” refers to fluidsor slurries used downhole during acidizing treatments. In one example,an acidizing fluid is used in a clean-up operation to remove materialobstructing the flow of desired material, such as material formed duringa perforation operation. In some examples, an acidizing fluid can beused for damage removal.

As used in this disclosure, the term “cementing fluid” refers to fluidsor slurries used during cementing operations of a well. For example, acementing fluid can include an aqueous mixture including at least one ofcement and cement kiln dust. In another example, a cementing fluid caninclude a curable resinous material such as a polymer that is in an atleast partially uncured state.

As used in this disclosure, the term “water control material” refers toa solid or liquid material that interacts with aqueous materialdownhole, such that hydrophobic material can more easily travel to thesurface and such that hydrophilic material (including water) can lesseasily travel to the surface. A water control material can be used totreat a well to cause the proportion of water produced to decrease andto cause the proportion of hydrocarbons produced to increase, such as byselectively binding together material between water-producingsubterranean formations and the wellbore while still allowinghydrocarbon-producing formations to maintain output.

As used in this disclosure, the term “packer fluid” refers to fluids orslurries that can be placed in the annular region of a well betweentubing and outer casing above a packer. In various examples, the packerfluid can provide hydrostatic pressure in order to lower differentialpressure across the sealing element, lower differential pressure on thewellbore and casing to prevent collapse, and protect metals andelastomers from corrosion.

As used in this disclosure, the term “fluid” refers to liquids and gels,unless otherwise indicated.

As used in this disclosure, the term “subterranean material” or“subterranean formation” refers to any material under the surface of theearth, including under the surface of the bottom of the ocean. Forexample, a subterranean formation or material can be any section of awellbore and any section of a subterranean petroleum- or water-producingformation or region in fluid contact with the wellbore. Placing amaterial in a subterranean formation can include contacting the materialwith any section of a wellbore or with any subterranean region in fluidcontact therewith. Subterranean materials can include any materialsplaced into the wellbore such as cement, drill shafts, liners, tubing,casing, or screens; placing a material in a subterranean formation caninclude contacting with such subterranean materials. In some examples, asubterranean formation or material can be any below-ground region thatcan produce liquid or gaseous petroleum materials, water, or any sectionbelow-ground in fluid contact therewith. For example, a subterraneanformation or material can be at least one of an area desired to befractured, a fracture or an area surrounding a fracture, and a flowpathway or an area surrounding a flow pathway, in which a fracture or aflow pathway can be optionally fluidly connected to a subterraneanpetroleum- or water-producing region, directly or through one or morefractures or flow pathways.

As used in this disclosure, “treatment of a subterranean formation” caninclude any activity directed to extraction of water or petroleummaterials from a subterranean petroleum- or water-producing formation orregion, for example, including drilling, stimulation, hydraulicfracturing, clean-up, acidizing, completion, cementing, remedialtreatment, abandonment, aquifer remediation, identifying oil richregions via imaging techniques, and the like.

As used in this disclosure, a “flow pathway” downhole can include anysuitable subterranean flow pathway through which two subterraneanlocations are in fluid connection. The flow pathway can be sufficientfor petroleum or water to flow from one subterranean location to thewellbore or vice-versa. A flow pathway can include at least one of ahydraulic fracture, and a fluid connection across a screen, acrossgravel pack, across proppant, including across resin-bonded proppant orproppant deposited in a fracture, and across sand. A flow pathway caninclude a natural subterranean passageway through which fluids can flow.In some embodiments, a flow pathway can be a water source and caninclude water. In some embodiments, a flow pathway can be a petroleumsource and can include petroleum. In some embodiments, a flow pathwaycan be sufficient to divert from a wellbore, fracture, or flow pathwayconnected thereto at least one of water, a downhole fluid, or a producedhydrocarbon.

As used in this disclosure, a “carrier fluid” refers to any suitablefluid for suspending, dissolving, mixing, or emulsifying with one ormore materials to form a composition. For example, the carrier fluid canbe at least one of crude oil, dipropylene glycol methyl ether,dipropylene glycol dimethyl ether, dipropylene glycol methyl ether,dipropylene glycol dimethyl ether, dimethyl formamide, diethylene glycolmethyl ether, ethylene glycol butyl ether, diethylene glycol butylether, butylglycidyl ether, propylene carbonate, D-limonene, a C2-C40fatty acid C1-C10 alkyl ester (for example, a fatty acid methyl ester),tetrahydrofurfuryl methacrylate, tetrahydrofurfuryl acrylate, 2-butoxyethanol, butyl acetate, butyl lactate, furfuryl acetate, dimethylsulfoxide, dimethyl formamide, a petroleum distillation product offraction (for example, diesel, kerosene, napthas, and the like) mineraloil, a hydrocarbon oil, a hydrocarbon including an aromaticcarbon-carbon bond (for example, benzene, toluene), a hydrocarbonincluding an alpha olefin, xylenes, an ionic liquid, methyl ethylketone, an ester of oxalic, maleic or succinic acid, methanol, ethanol,propanol (iso- or normal-), butyl alcohol (iso-, tert-, or normal-), analiphatic hydrocarbon (for example, cyclohexanone, hexane), water,brine, produced water, flowback water, brackish water, and sea water.The fluid can form about 0.001 weight percent (wt %) to about 99.999 wt% of a composition, or a mixture including the same, or about 0.001 wt %or less, 0.01 wt %, 0.1, 1, 2, 3, 4, 5, 6, 8, 10, 15, 20, 25, 30, 35,40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, 96, 97, 98, 99, 99.9,99.99, or about 99.999 wt % or more.

EXAMPLES Example 1

Kerogen was isolated from a rock matrix by dissolving the rock using acombination of hydrochloric acid and hydrofluoric acid. The isolatedkerogen possibly contained undissolved iron sulfide or other minerals.

FIG. 4 shows the degradation of kerogen over time after treatment with amixture of sodium bromate and ammonium persulfate. 1.0 g of sodiumbromate and 1.0 g ammonium persulfate were dissolved in 50 mL of water.0.10 g of isolated kerogen was added to the solution and the solutionwas mildly-translucent black in color, as indicated in image 402, andthe pressure tube 404 was sealed 406. The time t=0 indicates that noheating has yet been applied. The mixture was heated to 100° C. in anoil bath, and within 20-30 minutes, the solution turned a blackish redcolor, as indicated in image 408. The mixture was heated for 24 hours,over which time the entirety of the kerogen dissolved. At 2 hours ofheating, the solution was a dark red color, as indicated in image 410.At 6 hours of heating, the solution was a medium red color, as indicatedin image 412. At 20 hours of heating, the solution was a relativelybright red color, as indicated in 414. FIG. 4 shows the degradation ofthe black kerogen over time.

It was also observed that sodium bromate at higher temperature, such as150° C., degraded kerogen. However, an orange solid precipitate forms,which is undesirable. The orange solid precipitate may be an iron(III)oxyhydroxide species, which are largely insoluble above pH=3. Ammoniumpersulfate alone causes a limited amount of kerogen degradation.However, a strong synergistic effect between sodium bromate and ammoniumpersulfate exists. When combined, sodium bromate and ammonium persulfatedegrade kerogen quickly and cleanly at 100° C. The bright red color (416in FIG. 4) is indicative of bromine gas formation.

Example 2

In order to establish the feasibility of degrading/etching kerogendirectly from the rock matrix, a series of experiments were performed.Kerogen-rich shale samples were cut to pieces smaller than 1 cm in alldimensions, then mechanically polished on one side to enable clearvisualization under a microscope. FIGS. 5A and 5B shows a scanningelectron microscope (SEM) image of kerogen-rich shale. The imagesdemonstrate the nature of interlacing that occurs between the rockmatrix (light gray) and organic matter (dark gray). The organic mattercan have a globular structure or more string-like configuration as shownin these images.

A small shale sample was then unmounted and added to a treatment fluidcontaining 0.4 g ammonium persulfate and 0.4 g sodium bromate in 10 mLof water for 20 hours at 100° C. The fluid was then cooled, the shalesample was removed from the fluid, and was dried in an oven. Afterdrying, SEM imaging was again performed and is shown in FIG. 6. Regionswhere kerogen previously filled the voids were significantlydeteriorated, leaving a small amount of weakened organic matter withenlarged pores. A series of tests (14 tests) were performed to study theamount of oxidizer required to etch the kerogen from the rock.Successful etching was achieved with 0.02 g of each oxidizer in 10 mL ofwater.

Example 3

A small shale sample of less than 1 centimeter (cm) in all dimensionswas cut from a core sample using a diamond saw. The sample wasmechanically polished first using 600 and 1200 grit silicon carbidepaper then with progressively finer diamond suspensions beginning at 3micrometer (μm) and continuing until reaching 0.05 μm. The polishedsamples were subsequently imaged via SEM for pretreatment analysis. Ahigh resolution image of kerogen was obtained, noting the coordinates ofthe kerogen position. The sample was then transferred to a glass tube,to which was added 10 mL of water, 0.02 g (0.2%) ammonium persulfate,0.02 g (0.2%) sodium bromate, and 0.2 (2%) g KCl. The tube was sealedand placed in an oil bath at 100° C. for 20 hours. The tube was thencooled, the shale sample was removed and dried in an oven at 50° C. Theshale sample was then reimaged by SEM, locating the position of thepreviously imaged kerogen-containing region

FIG. 7A shows an SEM image of a shale sample containing kerogen. FIG. 7Bshows an SEM image of the same location of the same shale sample afterthe sample was treated with a mixture of ammonium persulfate and sodiumbromate.

Example 4

Each of the rock samples used for the etching experiments of Example 3were mechanically characterized to ensure that the rock itself was notbeing damaged during the etching of the kerogen. Each sample was testedwith a nanoindenter by collecting force-displacement curves, and themechanical properties of the material such as the Young's modulus weredetermined both before and after the treatments. Ten indentations up to200 mN load were performed using a Berkovich diamond tip.

The rocks were weakened by exposure to the oxidizer as evidenced by areduced Young's modulus. Heating specimen of the same rock in pure wateralone did not change the Young's modulus. By treating the rock withoxidizers in combination with a salt such as potassium chloride (e.g.,2-7 wt %), minimal change in the rock's Young's modulus was observedeven in cases where the oxidizer concentration was high. For example,for the treatment described in Example 3, the indentation curves wereanalyzed, and the Young's modulus was determined to be 30 GPapre-treatment and 31 GPa post-treatment, demonstrating negligible changeto the rock stiffness/integrity.

Other Embodiments

It is to be understood that while the invention has been described inconjunction with the detailed description thereof, the foregoingdescription is intended to illustrate and not limit the scope of theinvention, which is defined by the scope of the appended claims. Otheraspects, advantages, and modifications are within the scope of thefollowing claims.

What is claimed is:
 1. A method of treating a subterranean formation,comprising: specifying a concentration of an oxidizer in an aqueouscomposition based at least in part on an amount of kerogen to degrade inthe subterranean formation; and placing the aqueous compositioncomprising the oxidizer at the concentration as specified through awellbore into the subterranean formation to degrade the kerogen.
 2. Themethod of claim 1, wherein specifying the concentration furthercomprises specifying the concentration of the oxidizer in the aqueouscomposition based at least in part on an amount of fluid downhole in thewellbore at time of placing the aqueous composition through the wellboreinto the subterranean formation.
 3. The method of claim 1, whereinspecifying the concentration further comprises specifying theconcentration of the oxidizer in the aqueous composition based at leastin part on a type of the kerogen in the subterranean formation.
 4. Themethod of claim 1, wherein specifying the concentration furthercomprises specifying the concentration of the oxidizer in the aqueouscomposition based at least in part on an amount of an iron sulfide inthe subterranean formation.
 5. The method of claim 1, wherein theaqueous composition comprises produced water, flowback water, brackishwater, Arab-D-brine, or seawater, or any combinations thereof.
 6. Themethod of claim 1, wherein the concentration of the oxidizer in theaqueous composition is less than 4 M, and wherein the aqueouscomposition comprises a salt at less than 20 weight percent (wt %) inthe aqueous composition.
 7. The method of claim 6, wherein the saltcomprises potassium chloride, sodium chloride, lithium chloride,potassium bromide, sodium bromide, lithium bromide, ammonium chloride,ammonium bromide, ammonium iodide, calcium chloride, magnesium chloride,strontium chloride, calcium bromide, magnesium bromide, strontiumbromide, calcium iodide, magnesium iodide, or strontium iodide, or anycombinations thereof.
 8. The method of claim 1, wherein the aqueouscomposition comprises an imidazolium, an imidazole, an ammonia, apyrrolidinium, a pyrrolidine, pyridinium, a pyridine, or a phosphonium,or any combinations thereof.
 9. The method of claim 1, wherein theaqueous composition comprises chloride, bromide, iodide,tetrafluoroborate, hexafluorophosphate, or sulfonate, or anycombinations thereof.
 10. The method of claim 1, wherein the aqueouscomposition comprises proppant.
 11. The method of claim 1, wherein theoxidizer comprises hydrogen peroxide, an inorganic peroxide, a bromate,a persulfate, a permanganate, a chlorate, an iodate, a perchlorate, aperiodate, or a perborate, or any combinations thereof.
 12. A method offracturing a subterranean formation penetrated by a wellbore,comprising: specifying a concentration of an oxidizer in a compositioncorrelative with an amount of kerogen to be treated in the subterraneanformation; treating the kerogen in the subterranean formation with thecomposition having the oxidizer at the specified concentration; andfracturing the subterranean formation.
 13. The method of claim 12,wherein specifying the concentration further comprises specifying theconcentration of the oxidizer in the composition correlative with anamount of fluid in the wellbore.
 14. The method of claim 12, wherein thecomposition comprises water and an ammonium salt, wherein theconcentration of the oxidizer in the composition is less than 4 M, andwherein treating the kerogen comprises degrading the kerogen.
 15. Amethod of treating a subterranean formation, comprising: placing anaqueous composition comprising a persulfate and a bromate into thesubterranean formation; and degrading kerogen in the subterraneanformation with the persulfate and the bromate.
 16. The method of claim15, wherein the persulfate comprises ammonium persulfate, and whereinplacing the aqueous composition into the subterranean formationcomprises pumping the aqueous composition into the subterraneanformation.
 17. The method of claim 15, wherein the bromate comprisessodium bromate.
 18. The method of claim 15, comprising fracturing thesubterranean formation, wherein the aqueous composition comprisesproppant.
 19. The method of claim 15, wherein concentration of thepersulfate in the aqueous composition is less than 1 M, andconcentration of the bromate in the aqueous composition is less than 2M.20. The method of claim 15, wherein the composition comprises potassiumchloride, sodium chloride, lithium chloride, potassium bromide, sodiumbromide, lithium bromide, ammonium chloride, ammonium bromide, ammoniumiodide, calcium chloride, magnesium chloride, strontium chloride,calcium bromide, magnesium bromide, strontium bromide, calcium iodide,magnesium iodide, or strontium iodide, or any combinations thereof.